VI. Elements Comprising the DWR Revenue Requirement

DWR computes its revenue requirement in a two-step process. Step 1 involves the aggregate determination of DWR's gross expenditures. In Step 2, DWR applies proceeds from its forecast external interim financing to determine the net remaining amount that it needs to collect from utility customers over the two year period and submits that amount to the Commission as its AB1X-authorized revenue requirement. The revenue requirement includes recorded amounts for prior months dating back to January 17, 2001, and includes forecast amounts for future months through December 31, 2002.

DWR's revenue requirement for all three utilities reflecting the allowed adjustments, totals $9.045 billion, as summarized in Appendix A of this decision. The revenue requirement represents total expenditures of $18.014 billion, less the proceeds from external financings. The remaining balance of $9.045 billion is the DWR revenue requirement to be recovered from utility customers covering the period from January 17, 2001 through December 31, 2002, and reflects an aggregate amount for customers of all three electric utilities' service territories. The $9.045 billion revenue requirement is the amount before deducting interim proceeds that have already been remitted to DWR by the utilities' customers on an interim basis.

DWR reports its revenue requirement in accordance with the categories specified in Water Code Section 80134, together with certain additional detail:15

· Operating expenses, including purchased power under fixed price and short term contracts, as well as ancillary services.

· Administrative and Overhead

· Demand Side Management

· Allowance for Uncollectibles

· Lead (Lag) Accrual to Cash

· Interim Loan Costs

A summary of DWR's revenue requirement is set forth in the Appendix A of this order. These elements are summarized below.

A. Long Term and Short Term Power Purchases

DWR's forecast of total operating expenses from January 17, 2001 through December 31, 2002 for the three utilities includes $5.284 billion for long-term contract power, and $9.534 billion for residual net short-term purchases.16 .

"Long-term" contracts are those that are more than 90 days in duration. The costs associated with purchases under long term contracts in existence as of November, 2001 are shown in the column labeled "Contract Power" in Table 1 below. An estimate of the energy associated with long-term purchases is shown in the column labeled "Contracts" in Table 2 below.

"Short-term" contracts generally consist of bilateral contracts longer than day-ahead purchases with a duration of 90 days or less. For contracts in place as of October 1, 2001, these are a component of the column labeled "Residual Net Short" in Table 1. An estimate of the energy associated with short-term purchases is a component of the column in Table 2 labeled "Residual Net Short Purchases."

Table 1 below summarizes on quarterly basis the average cost per megawatt-hour (mWh) of power acquired by DWR over the 24-month period. Table 2 summarizes the total DWR purchases, by long-term and short-term amounts.

TABLE 1

AVERAGE NET SHORT ENERGY COSTS

($/MWH)

DWR

Contracts

Residual Net

Short

Weighted Average

Power Cost

Q12001

-

269

269

Q2 2001

132

249

222

Q3 2001

128

117

121

Q4 2001

121

42

79

Q12002

115

36

78

Q2 2002

143

30

87

Q3 2002

118

38

84

Q4 2002

111

36

82

TABLE 2

ESTIMATED DWR ENERGY PURCHASES

(GWH)

Total Net Short

Purchases

Contracts

Residual Net Short

Purchases

Q3 2001

16,054

6,929

9,125

Q4 2001

11,312

5,361

5,951

Q12002

10,153

5,466

4,687

Q2 2002

8,648

4,391

4,257

Q3 2002

13,399

7,660

5,739

Q4 2002

11,788

7,239

4,549

The DWR cost per mWh shown in Table 1 and energy purchases shown in Table 2 exclude any sales to Direct Access customers. Transmission- and distribution-related costs have not been included in DWR's revenue requirement and are presumed to be covered by the utilities 's own rates. Fuel costs are included in the total energy costs through the use of a generation dispatch model based on quantity and price of energy. The natural gas price assumptions used in DWR's analysis are described in Appendix C.

B. Ancillary Service Costs

DWR estimates ancillary service cost responsibility of $1.102 billion using a proxy for procured capacity and composite ancillary service market prices, adjusted for other ancillary services charge responsibilities not incorporated therein. DWR used data collected from June 1999 through November 2000 to compare (1) monthly historical ancillary services capacity procured on the market (including self provision) to the monthly system load, and (2) the monthly composite ancillary services price to the spot market price. Historical ancillary services market capacity was calculated as 13% of load for the period. Historical ancillary services composite price (weighted average of spin, non-spin, regulation up, regulation down, and replacement reserves) was calculated as 31% of spot market prices.

DWR made an adjustment to account for expected self-provided ancillary services costs for which DWR would not bear cost responsibility. In addition, ancillary service costs based on IOU data received November 1, 2001 reflecting the period from January 17 through October 2001 have been included in the revenue requirement net of self-provision by the utilities.

C. Administrative, General, and Overhead

DWR's estimated administrative and general expenses (A&G) expenses of $99 million are summarized by quarter in Appendix A in the column labeled "A&G." Table 3 below provides more detail on the A&G expenses of DWR.

TABLE 3

ADMINISTRATIVE, GENERAL, AND OVERHEAD EXPENSES

(MILLIONS OF DOLLARS)

Labor

(Including

Benefits)

Capital

Expenditures

Professional

Service Fees

Other

Administrative

and General

Expenses"'

Q12001

$2

$1

$5

$2

Q2 2001

2

1

5

2

Q3 2001

2

1

5

2

Q4 2001

2

1

5

2

Q12002

2

5

6

1

Q2 2002

2

5

6

1

Q3 2002

2

5

6

1

Q4 2002

2

5

6

1

Total

$16

$24

$44

$13

'Other Expenses include costs of administration and billing related to the 20/20 Program in 2001.

Total A&G costs do not tie to Appendix A totals due to rounding.

D. Conservation/Load Management Costs

Table 4 below presents actual and expected conservation and load management costs by quarter included in the revenue requirement. DWR has included costs and associated energy savings for 2002 only for energy conservation and load management programs that have been authorized by either Executive Order of the Governor or by statute.17 No such programs involving funding by the DWR as part of the net short energy procurement program have been authorized for 2002 and, therefore, no costs have been assumed. Any net short energy requirements (after the effects of conservation or DSM programs funded by the IOUs or others) are assumed to be met either by energy from DWR contract purchases or spot market purchases. Although the ISO may have incurred costs for voluntary load reduction programs for the summer of 2001, DWR has not considered those cost as part of its revenue requirement.

TABLE 4

COSTS TO AVOID OR MINIMIZE THE AMOUNT OF ACQUIRED POWER

(MILLIONS OF DOLLARS)

Conservation

Programs

Load

Curtailment Interruptible

Programs

Conservation

Rebates

Load

Management

Programs

Q12001

-

-

-

-

Q2 2001

3

-

1

-

Q3 2001

5

-

226

-

Q4 2001

-

-

62

-

Q12002

-

-

-

-

Q2 2002

-

-

-

-

Q3 2002

-

-

-

-

Q4 2002

-

-

-

-

E. Allowance for Uncollectibles

Included in DWR's revenue requirement is an allowance for uncollectible accounts. The allowance for uncollectible accounts was developed based on the DWR's assuming a pro rata share of recently observed utility uncollectible accounts. These amount to $7.7 million for calendar year 2001 and are expected to approximate $16 million during calendar year 2002.

DWR includes in its allowance an uncollectible factor of 0.0033. (Reference Item E, transcript of October 22, 2001 workshop, RT 81:22-82:12.) Aglet opposes DWR cost recovery of uncollectibles based on the untested average rate of 0.0033, but instead advocates use of the most recently authorized uncollectibles factor for each utility. For example, the authorized factor for PG&E is 0.00267, which is 19% lower than DWR's figure. (Decision 01-10-031, Ordering Paragraph 27, slip op. at 45.)

Aglet argues that reliance on Commission-authorized uncollectibles factors will treat customers fairly and will have no effect on DWR's achieved revenues. Customer rates for each utility would include an uncollectibles allowance based on the authorized rate, billed revenues would be reduced using the authorized rate, and remaining cash revenues would be available for transmittal to DWR. Aglet argues that this outcome is administratively efficient because each utility will use a single uncollectibles factor for all of its retail rates, rather than determining rates based on two different factors.

DWR has explained that its forecasted allowance for uncollectibles was developed assuming a pro rata share of recently observed utility uncollectible accounts. (Reference Item C, DWR, November 5 revenue requirement document, p. 19.) As stated previously, DWR is charged with determining the justness and reasonableness of its revenue requirement, and this proceeding is not the forum in which to litigate the reasonableness of DWR's determination of this element of its revenue requirements. In the true-up of DWR's forecasted versus actual revenue requirement, relevant differences in uncollectibles expense can be taken into account.

In any event, whatever assumptions DWR makes concerning uncollectibles in its revenue requirements determination, we do not intend for the utilities to retain uncollectible allowances in excess of the amounts that have been adopted for utility ratemaking purposes. In this decision, we do not endorse the DWR uncollectibles factor of 0.0033.

F. Lead (Lag) Accrual to Cash

DWR adjusts its revenue requirement to account for the difference in time between the expenditure of cash to provide services to customers and the receipts of cash from them. Such amounts, totaling $401 million (lead), for the Revenue Requirement Period are included in Appendix A under the column labeled "Lead (Lag) Accrual to Cash." Leads (lags) are also used to adjust DWR's total operating costs to derive its total operating expenditures.

These leads or lags can vary depending on the type of expense lead (i.e., payments by DWR for its contractual commitments versus payments for purchases of residual net short vs. payments by DWR to its other suppliers) and the revenue lag (i.e., the average amount of time it takes the DWR to receive payment for services provided). Some of the expense lags are defined within contracts or per the rules of the markets from which DWR arranges for purchases of residual net short. For the purpose of calculating the DWR revenue requirement, a revenue lag of 45 days was assumed for all prescheduled purchases by DWR. Revenues for all purchases by the ISO going forward are assumed to lag 90 days. Revenues attributed to ISO real-time and out-of-market purchases which have been procured for grid reliability have not been paid to date. They are assumed to be fully paid by February 2002. Expense lags are assumed to be as follows:

Contract expense: paid in 20 days;

Pre-scheduled residual net short energy: paid in 8 days; and

Other expenses: paid in 20 days.

G. Interim Loan Costs

Interim loan costs are included in the DWR's revenue requirement as displayed in the column labeled "Financing Cost" in Appendix A. These costs represent principal and interest payments on a $4.3 billion interim financing entered into by the DWR on June 26, 2001. The interim loan proceeds reduce the amount of revenues that would otherwise be required currently from customers. DWR plans to retire this interim financing from the proceeds of long-term bonds, expected to be issued during the second quarter of 2002. Nonetheless, DWR explains that in order to stay within the terms of the interim financing, DWR must determine its revenue requirement on the assumption that bonds are not issued, to continue until bonds actually are issued. This requirement means that debt service costs of the interim financing are included for the entire period of the filing to protect DWR and lenders from exposure should bonds not be issued when expected.

In addition, DWR explains that ongoing debt service "coverage" tests must be met for the interim financing. If long-term bonds are not issued in the first half of 2002, DWR may need to reevaluate its revenue requirement for the balance of this revenue requirement filing period and for future periods. When the long-term bond financing is completed, DWR states that it will evaluate its revenue requirement and make any necessary adjustments.

AB1X authorizes DWR to issue up to approximately $13 billion in bonds to support its power purchase program. Until the bonds are sold, DWR is relying on the interim borrowing arrangements.

A relatively small portion of the proceeds from the bonds will be used to fund future power purchases, as a supplement to the retail revenue requirement collected from customers in the utilities service territories. Future ratepayers will service the repayment of bond principal, together with accrued interest, in addition to paying for DWR power that they consume. Bond structure and size is an issue exclusively committed to the discretion of DWR. As developed more fully below, this decision applies the Commission's traditional ratemaking authority for DWR electricity sales, as shaped and directed by the Legislature in AB1X.

PG&E believes that DWR need not and should not increase revenue requirements to reflect interim financing costs which the projected surplus in the DWR Power Fund can cover prior to the expected issuance of DWR's power revenue bonds. Given this surplus, PG&E believes that DWR's power revenue bonds can and should be issued in time to avoid the need for any revenue requirement increase for the interim loan.

PG&E claims, however, that for DWR to increase its revenue requirement to cover interim loan costs while at the same time building up a surplus in the Power Fund which exceeds that amount constitutes a form of double-charging to PG&E's customers. PG&E argues that under DWR's own financial projections, the beginning and ending quarterly balance in DWR's Power Fund in each of the second through fourth quarters of 2002 will far exceed the 110% coverage ratio required under DWR's Interim Loan. PG&E asserts the ratio is exceeded even after subtracting out the $1.338 billion in additional revenues requested by DWR to cover financing costs during the same period. Therefore, PG&E argues that DWR should reduce its revenue requirement to reflect payment of interim loan costs out of its Power Fund surplus, while at the same time reserving its rights to request a change in its revenue requirement during the next revenue requirement period, should its forecast power costs significantly change.

SCE similarly argues that DWR's revenue requirement should be approximately $940 million lower to reflect interim financing costs that will not be incurred, assuming that the bonds are issued as expected in the second quarter of 2002, with the bond proceeds paying off the interim loan.

Because of the requirements of the Interim Loan, as explained above, DWR has retained interim loan costs in its revenue requirement on the assumption that bonds will not be issued in the summer of 2002. DWR's February 21, 2002 letter allows for the removal of a portion of these costs, but a significant portion still remains. Particularly in view of the significant level of costs projected for DWR's interim loan, we strongly recommend to DWR that it promptly remove the interim loan costs from its revenue requirement if it subsequently determines that it will not incur those costs. If, in fact, the long-term bonds are issued at the end of June 2002, as now anticipated, DWR will not need to incur the interim loan costs that it has included in its revenue requirement for the latter quarters of 2002. We are scheduling the next updating of DWR's revenue requirement to begin June 1, 2002 (as discussed later in this order). We expect DWR to provide an adjustment to its revenue requirement at or before that time, reflecting the removal of the interim loan costs if, in fact, it still expects the long term bonds to be issued on schedule at the end of June 2002. Upon removal of those interim loan costs by DWR, if these sums are not needed to pay interest on the long term bonds or to reimburse the General Fund, we would expect to be able to implement a prompt adjustment to the DWR remittance charges payable by the utilities for the balance of 2002.

H. Deposits to Fund or Replenish Operating Reserves

The fund into which revenues collected from DWR's purchase program are deposited, from which DWR expenses are paid, and in which operating reserves are held, is defined as the "Power Fund." The Power Fund balance currently consists of the unexpended proceeds of the Department's interim financing and revenues fromthe sale of power to Customers and to off-system buyers. The fund balance of the Power Fund is projected to grow during the period of this filing due to the need to make interim financing principal and interest payments and provide debt service coverage for the interim financing. DWR states that operating reserves will need to be replenished only if costs are significantly higher than the assumptions that underlie the Department's revenue requirement as presented in this filing.

15 DWR explained in Exhibit C of its August 7 update how its forecasted cost categories are consistent with Water Code Section 80134. 16 "Residual net short purchases" include all net short purchases other than ancillary services, in addition to DWR power purchases under bilateral contracts. 17 Appendix II and Appendix VI of DWR's November 5 submittal provide further details on these programs in terms of the description of the programs, the amount of savings in MWh per month, and the associated costs for these programs and savings.